1. Field of the Invention
The invention relates generally to the exploitation of hydrocarbon-containing formations. More specifically, the invention relates to fluids that are used to optimize and/or enhance the production of hydrocarbon from a formation (“well completion fluids”).
2. Background Art
Hydrocarbons (oil, natural gas, etc.) are typically obtained from a subterranean geologic formation (i.e., a “reservoir”) by drilling a well that penetrates the hydrocarbon-bearing formation. In order for hydrocarbons to be “produced,” that is, travel from the formation to the wellbore (and ultimately to the surface), there must be a sufficiently unimpeded flowpath from the formation to the wellbore. This flowpath is through the formation rock, e.g., solid carbonates or sandstones having pores of sufficient size, connectivity, and number to provide a conduit for the hydrocarbon to move through the formation.
Recovery of hydrocarbons from a subterranean formation is known as “production.” One key parameter that influences the rate of production is the permeability of the formation along the flowpath that the hydrocarbon must travel to reach the wellbore. Sometimes, the formation rock has a naturally low permeability; other times, the permeability is reduced during, for instance, drilling the well. When a well is drilled, a drilling fluid is often circulated into the hole to contact the region of a drill bit, for a number of reasons such as: to cool the drill bit, to carry the rock cuttings away from the point of drilling, and to maintain a hydrostatic pressure on the formation wall to prevent production during drilling. During well operations, drilling fluid can be lost by leaking into the formation. To prevent this, the drilling fluid is often intentionally modified so that a small amount leaks off and forms a coating on the wellbore surface (often referred to as a “filtercake”). Once drilling is complete, and production is desired, this coating or filtercake must be removed.
Additionally, during production, water containing a number of dissolved salts is often coproduced with the hydrocarbon. Especially when the formation is a carbonate, calcium cations are prevalent, as are carbonate and phosphate anions. The combination products of calcium cation with carbonate anion or phosphate anion will precipitate from the water in which the ions are carried to form “scale” deposits when the concentrations of these anions and cations exceed the solubility of the reaction product. The formation of scale can slow oil production rate and, in extreme circumstances, stop production completely.
A variety of solutions to prevent the formation of scales in a wellbore have been proposed. One typical method is to inject or “squeeze” a solution of a “scale inhibitor” such as a polyphosphonate into the reservoir rock, often utilizing a brine or water afterflush, and allow the absorbed inhibitor to desorb during fluids production. In practice, however, the desorption process is often found to be quite rapid once production is resumed, thereby necessitating frequent shutdowns for additional treatments. This has the effect of substantially reducing the productivity of the well.
Techniques used to increase the net permeability of the reservoir are referred to as “stimulation” techniques. Typically, stimulation techniques include methods such as: (1) injecting chemicals into the wellbore to react with and dissolve the damage (e.g., scales, filtercakes); (2) injecting chemicals through the wellbore and into the formation to react with and dissolve small portions of the formation to create alternative flowpaths for the hydrocarbon; and (3) injecting chemicals through the wellbore and into the formation at pressures sufficient to actually fracture the formation, thereby creating a large flow channel through which hydrocarbon can more readily move from the formation into the wellbore.
In particular, methods to enhance the productivity of hydrocarbon wells (e.g., oil wells) by removing (by dissolution) near-wellbore formation damage or by creating alternate flowpaths by fracturing and dissolving small portions of the formation at the fracture face are respectively known as “matrix acidizing,” and “acid fracturing.” Generally speaking, acids, or acid-based fluids, are useful in this regard due to their ability to dissolve both formation minerals (e.g., calcium carbonate) and contaminants (e.g., drilling fluid coating the wellbore or penetrated into the formation) introduced into the wellbore/formation during drilling or remedial operations.
Both the inhibition or removal of filtercakes and scales, and fluid placement are key concerns in well completion operations. Typical prior art techniques involve a multiple stage process. For example, in a typical prior art application, during completion operations, an acid treatment is performed, followed by a spacer. After this treatment, the well is cleaned, and a scale inhibitor is injected. A spacer is then injected, followed by a diverter. The process of additive (which may be an acid or a diverter, for example), spacer, additive, spacer, is repeated until all of the required treatments have been finished. This is a costly and time-consuming procedure.
Typically, matrix acidizing treatments have three major limitations: (1) limited radial penetration; (2) non-optimal axial distribution; and (3) corrosion of the pumping and well bore tubing. The first problem, limited radial penetration, occurs because once the acid is introduced into the formation (or wellbore), the acid reacts very quickly with the wellbore coating or formation matrix (e.g., sandstone or carbonate). In the case of treatments within the portion of the formation (rather than wellbore treatments), the formation near the wellbore that first contacts the acid is adequately treated. However, because most or all of the acid reacts upon contact, portions of the formation more distal to the wellbore (as one moves radially outward from the wellbore) remain untouched by the acid.
For instance, sandstone formations are often treated with a mixture of hydrofluoric and hydrochloric acids at very low injections rates (to avoid fracturing the formation). This acid mixture is often selected because it will dissolve clays (found in drilling mud) as well as the primary constituents of naturally occurring sandstones (e.g., silica, feldspar, and calcareous material). In fact, the dissolution is so rapid that the injected acid is essentially spent by the time it reaches a few inches beyond the wellbore. As a result, over 100 gallons of acid per foot is required to fill a region five feet from the wellbore (assuming 20% porosity and 6-inch wellbore diameter).
Similarly, in carbonate systems, the preferred acid is hydrochloric acid, which again, reacts so quickly with the limestone and dolomite rock that acid penetration is limited to between a few inches and a few feet. In fact, due to such limited penetration, it is believed matrix treatments are limited to bypassing near-wellbore flow restrictions—that is, they do not provide significant stimulation beyond what is achieved through (near-wellbore) damage removal. Yet damage at any point along the hydrocarbon flowpath can impede flow (hence production). Therefore, because of the prodigious fluid volumes required, these treatments are severely limited by their cost.
A second major problem that severely limits the effectiveness of matrix acidizing technology, is non-optimal axial distribution. This problem relates to the proper placement of the acid-containing fluid—i.e., ensuring that it is delivered to the desired zone (that is, the zone that needs stimulation) rather than another zone.
More particularly, when a hydrocarbon-containing carbonate formation is injected with acid (e.g., hydrochloric acid), the acid begins to dissolve the carbonate. As acid is pumped into the formation, a dominant channel through the matrix is inevitably created. As additional acid is pumped into the formation, the acid naturally flows along that newly created channel—i.e., the path of least resistance—and, therefore, leaves the rest of the formation untreated. This, of course, is undesirable. It is exacerbated by intrinsic heterogeneity with respect to permeability (common in many formations)—this occurs to the greatest extent in natural fractures in the formation and due to high permeability streaks.
Again, these regions of heterogeneity in essence attract large amounts of the injected acid, hence keeping the acid from reaching other parts of the formation along the wellbore—where it is actually needed most. Thus, in many cases, a substantial fraction of the productive, oil-bearing intervals within the zone to be treated are not contacted by acid sufficient to penetrate deep enough (laterally in the case of a vertical wellbore) into the formation matrix to effectively increase its permeability and therefore its capacity for delivering oil to the wellbore.
The problem of proper placement is significant in these systems because the injected fluid preferentially migrates to higher permeability zones (the path of least resistance) rather than to the lower permeability zones—yet it is those latter zones which require the acid treatment (i.e., because they are low permeability zones, the flow of hydrocarbon through them is restricted). In response to this problem, numerous, disparate techniques have evolved to achieve more controlled placement of the fluid—i.e., to divert the acid away from naturally high permeability zones and zones already treated and towards the regions of interest. A variety of prior art techniques (including emulsified acid systems, foamed systems, mechanical systems, and gelling agents) have been developed to control acid placement.
It has been difficult to find systems compatible over a wide range of temperatures with the wide variety of additives that are commonly used in well completion fluids that are suitable for inhibiting scale formation and can be properly, placed (i.e., self diverting).
Accordingly, what is desired are fluids that can inhibit the formation of scales and can be easily “spotted” or placed in the wellbore over the entire length of the desired zone. In addition, what is desired are fluids that are compatible with a wide range of additives over a broad range of temperatures and concentrations.